Method for the in-situ generation chlorine dioxide

ABSTRACT

The invention relates to the in-situ generation of chlorine dioxide for the treatment of hydrocarbon processing systems. The composition comprises a source of chlorite, a source of persulfate and water. Under the specified conditions of temperature and/or halide catalyst, chlorine dioxide is generated at an increased rate, thereby effectively treating down-hole hydrocarbon recovery systems.

RELATED APPLICATIONS

This Non-Provisional application is a continuation of Provisional Application No. 61/958,938 filed on Aug. 10, 2013.

TECHNICAL FIELD

The claims recite a method for the in-situ generation of chlorine dioxide for use in hydrocarbon recovery systems, such as, but not limited to, the use of chlorine dioxide for the treatment of geologic formations, high temperature formation fluids, well processing fluids, well drilling, and hydraulic fracturing. More particularly, the claims recite a method comprising an aqueous solution of persulfate (e.g., sodium persulfate) and a chlorite (e.g., sodium chlorite), and contacting said aqueous solution with said hydrocarbon recovery systems.

BACKGROUND

In the petroleum industry, numerous agents or contaminants can cause damage to or restriction of the production process. Examples of such contaminates can be high-molecular weight polymers (e.g. polyacrylamides, carboxymethylcellulose, hydroxyethylcellulose, CMC, HPG, and Zanthan), bacteria, sulfur, iron sulfide, hydrogen sulfide and similar compounds. These contaminants can, in some cases, occur naturally in a formation or be present from prior human interactions. For example, bacteria are commonly introduced to a formation during drilling and workover (e.g. the repair or stimulation of an existing production well) operations. Similarly, during a fracturing process, bacteria are often introduced into the wellbore and forced deep into the formation. More specifically, polymers such as CMC, HPG, Zanthan, and polyacrilomides are added to the fracturing fluid to maintain the proppant in suspension and to reduce the friction of the fluid. Bacteria entrained within this fluid penetrate deep into the formation, and once frac pressure is released, become embedded within the strata in the same manner as the proppant deployed. Additionally, polymers can also be deposited within the formation, causing damage in their own right. Typically, conventional “breakers” are added to the fracturing fluid along with the polymer to prevent this problem, but damage to producing wells due to the incomplete destruction of polymers remains a common occurrence. Producing wells typically require the use of water for many different applications. Some non-limiting examples of applications that use said water include: the removal of accumulated salts from down-hole pumps; water flooding to displace more petroleum in the geologic formation toward the collection well, and power fluid used for operating jet pumps to extract formation fluids. Furthermore, high electrolyte solutions recovered from the formation fluid, known as produced water, sometimes requires disposal in wells and requires treatment to prevent inoculating the formation with bacteria.

Many bacteria are facultative, that is they can exist in aerobic or anaerobic conditions using either molecular oxygen or other oxygen sources to support their metabolic processes. For example, under the right conditions, facultative bacteria can use sulfate as an oxygen source and respire hydrogen sulfide, which is highly toxic to humans in addition to being corrosive to steel. Additionally, in a process known in the art as Microbiologically Induced Corrosion (MIC), bacteria will attach to a substrate, such as the wall of a pipe in the wellbore, and form a “biomass” shield around them. Underneath, the bacteria metabolize the substrate (e.g. a mixture of hydrocarbon and metallic iron) and respire hydrogen sulfide, resulting in the metal becoming severely corroded in the wellbore and, eventually, pipe failure and damage to down-hole equipment. The respiration and presence of hydrogen sulfide also complicates the refining and transportation process, and attenuates the economic value of the produced hydrocarbon.

The traditional methods, when used alone to address these problems, have one or more drawbacks. For example, the present industry practice is to add conventional organic and inorganic biocides, such as quaternary ammonium compounds, chloramines, aldehydes, such as Gluteraldehyde, THPS and sodium hypochlorite, to fracturing fluids with other additives to control bacteria. The efficacy of these conventional biocides alone, however, can be minimal due to the type of bacteria that typically are found in hydrocarbon-bearing formations and petroleum production environments. More particularly, only a small percentage of these bacteria, which are often found in volcanic vents, geysers, and ancient tombs, are active at any one time; the remainder of the population is present in dormant and spore states. The aforementioned conventional biocides have no, or limited, effect on dormant and spore forming bacteria. Thus, while the active bacteria are killed to some extent, the inactive bacteria survive and thrive once they reach the environmental conditions found within the formation. Additionally, these biocides become inactivated when exposed to many of the components found in petroleum production formations. And, furthermore, microorganisms build resistance to these biocides, thus limiting their utility over time.

Chlorine dioxide, on the other hand, can inactivate or kill active, dormant and spore forming microorganisms. Unlike conventional biocides, microorganisms do not build a resistance to chlorine dioxide, and it has a low residual toxicity and produces benign end products. Chlorine dioxide is therefore an efficacious biocide, however certain applications have not been possible prior to the invention. For example, although chlorine dioxide can be applied directly to well fluids (for example, fracturing water) for disinfection, it can only be applied at a low dosage to prevent degradation of polymer(s) or other drag reduction additives.

Embodiments of this invention provide for a method for the in-situ generation of chlorine dioxide in hydrocarbon recovery systems, said method comprising the steps of: combining a source of chlorite, a source of persulfate and water to form a composition; the molar ratio of chlorite (having the general formula ClO₂ ⁻) to persulfate (having the general formula S₂O₈ ^(═)) being greater than 0.5:1, more preferably greater than or equal to 1:1, and most preferred greater than or equal to 2:1; introducing said composition into a hydrocarbon recovery system; achieving a temperature of greater than 100° F., and wherein all or part of the chlorite is converted to chlorine dioxide in the hydrocarbon recovery system.

One or more embodiments of the invention, which incorporate this method for the in-situ generation of chlorine dioxide into a fracturing fluid, thus provide an in-situ method for generating and using chlorine dioxide as a polymer oxidant and down-hole biocide that does not deplete or attenuate the friction-reducing components of the fracturing fluid until the generation of chlorine dioxide is accelerated by elevated temperature. In these embodiments, the chlorine dioxide acts as a polymer oxidant and down-hole biocide.

Another embodiment of the invention is the stimulation of petroleum recovery systems (e.g. hydrocarbon containing geologic formation) to increase the flow-rate of formation fluids. Chlorine dioxide oxidizes bio-films and chemically reducible compounds that restrict flow, thereby improving permeability within the formation.

The embodiments disclosed herein provide for results that cannot be accomplished with ex situ generated halogen dioxides, such as chlorine dioxide, or other halogen dioxide precursors alone, such as sodium chlorite. For example, chlorine dioxide cannot be added to well fluids (e.g. fracturing fluid) at high concentrations prior to injection into the wellbore because the chlorine dioxide will prematurely oxidize the polymers and friction-control additives within the fracturing fluid. By contrast, embodiments of the present invention remain generally stable until exposed to a minimum temperature located within a subterranean formation or otherwise provided in a hydrocarbon recovery system (i.e. high temperature fluid streams, a pipeline or geologic formation). Furthermore, the treatment of water and additives used as fracturing fluid with chlorine dioxide results in the reduction of chlorine dioxide back to chlorite. Residual persulfate present in the solution, when exposed to higher temperatures, begins the slow process of regenerating the chlorite back to chlorine dioxide thereby treating the hydrocarbon recovery system without the need for high concentrations of chlorine dioxide that can, as previously described, be detrimental to the fracturing fluid.

Thus, embodiments of the invention provide a method, under specified conditions, for the in-situ generation of at least chlorine dioxide that is capable of 1) degrading polymers within a subterranean formation); 2) reducing toxic and unwanted sulfur compounds within the hydrocarbon recovery systems (i.e. the subterranean formation, hydrocarbon deposits, formation fluids); 3) functioning as a biocide that kills or destroys bacteria in active, dormant and spore forms; 4) treating the hydrocarbon recover system to increase the recovery of formation fluids; 5) reducing corrosion of steel comprising hydrocarbon recovery equipment, and 6) remediation of sour (e.g. hydrogen sulfide) wells and geologic formations.

BRIEF DESCRIPTION OF THE INVENTION

Chlorine dioxide is a very effective biocide and oxidant for reducing or removing undesirable contaminates (i.e. bacteria, sulfur compounds) in hydrocarbon recovery systems. However generating high concentrations of chlorine dioxide increases risk to workers (i.e. inhalation, explosion), and the use of high concentrations of chlorine dioxide may induce other problems such as corrosion to equipment and oxidation of other chemicals used for various hydrocarbon recovery applications such as hydraulic fracturing.

The disclosed method provides for the in-situ generation of chlorine dioxide that provides improved down-hole treatment of hydrocarbon recovery systems. The improved down-hole treatment is the result of generation of chlorine dioxide as the aqueous solution comprising chlorite and persulfate travels down the well, contacts the piping, geologic formation and/or formation fluid under conditions that increase the rate of in-situ generation of chlorine dioxide (e.g. increased temperature and/or contact with a catalytically effective amount of halide). Furthermore, the catalyzed in-situ generation of chlorine dioxide resulting from contact between the aqueous solution comprising chlorite and persulfate and formation fluid comprising a catalytically effective amount of halide (e.g. bromide, chlorite) results in treating the hydrocarbon recovery system as the combined fluids return back to the surface. There is considerable economic benefit resulting from the regeneration of chlorite from reduced chlorine dioxide. Chlorine dioxide used for treating water and fracturing fluids on the surface is reduced to chlorite anions. These chlorite anions can be regenerating using the method disclosed and therefore, the chlorine dioxide is a source of chlorite.

The present invention provides in accordance with a first aspect, a method for the in-situ generation of chlorine dioxide in hydrocarbon recovery systems, said method comprising the steps of: producing an aqueous solution comprising a source of chlorite and a source of persulfate to form a composition; the molar ratio of chlorite (having the general formula ClO₂ ⁻) to persulfate (having the general formula S₂O₈ ^(═)) being greater than 0.5:1, more preferably greater than or equal to 1:1, and most preferred greater than or equal to 2:1; introducing said composition into a hydrocarbon recovery system; achieving a temperature of greater than 100° F., and wherein all or part of the chlorite is converted to chlorine dioxide in the hydrocarbon recovery system.

The concentration of chlorite is in a sufficient amount to generate from 2 to 10,000 ppm chlorine dioxide, and the concentration of persulfate is in a sufficient amount to achieve a molar ratio of chlorite (having the general formula ClO₂ ⁻) to persulfate (having the general formula S₂O₈ ^(═)) of greater than 0.5:1, more preferably greater than or equal to 1:1, and most preferred greater than or equal to 2:1. The aqueous solution comprising chlorite and persulfate can be prepared by mixing or blending the source of chlorite and source of persulfate to produce an aqueous solution prior to addition to the hydrocarbon recovery system. The source of chlorite and source of persulfate may be added separately using chemical metering pumps, venture, manually or any convenient means available. The aqueous solution comprising chlorite and persulfate may be batch fed wherein the solution is fed at one time, intermittently fed, or fed continuously during normal operations as needed.

In one or more embodiments, in accordance with the first aspect of the invention, the composition may include additives exemplified by hydrotropes, surfactants, dispersants, chelants, sequestrants, acids, and corrosion inhibitors to provide additional benefits by removing deposits, preventing their re-deposition, and protecting the exposed metal piping from corrosion.

In one embodiment, the composition may further comprise at least one nonionic surfactant in a concentration of from 0.005 to 3% w/w, preferably from 0.01 to 2% w/w, more preferably from 0.02 to 1% w/w, based on the total weight of the solution. Furthermore, the at least one nonionic surfactant is preferably chosen from (a) ethoxylated alcohols and alkylglycosides having a hydrophile lypohile balance from 5 to 15, which may be a C6-C10 alkyl, 3-9 moles of ethylene oxide (EO) alcohol ethoxylate; and (b) a sufficiently water-soluble block copolymer of ethylene oxide or propylene oxide.

In yet another embodiment, the composition may further comprise at least one cation sequestering agent in a concentration of from 0.0001 to 1.0% w/w, preferably from 0.0005 to 0.1% w/w, more preferably from 0.001 to 0.01% w/w, based on the total weight of the solution. The cation sequestering agent may be 1-hydroxyethylidene-1,1-diphosphonic acid, or phosphonobutane tricarboxylic acid.

In still another embodiment of the invention, the composition may contain at least one anionic surfactant chosen from (a) C8-C16 alkyl benzene sulfonic acids and alkali metal, alkaline earth metal, ammonium or alkylamine salts thereof; (b) C8-C18 alkyl sulfonic acid; (c) C8-C16 alkyl sulfates; and (d) C6-C12 alkyl diphenyl oxide sulfonate surfactants, in a concentration of from 0.001 to 1% w/w, or from 0.01 to 0.5% w/w, based on the total weight of the solution. The at least one anionic surfactant may be an alkyl benzene sulfonic acid and, preferably, dodecyl benzene sulfonic acid.

In one or more embodiments, the composition may comprise at least one polymeric dispersant in a concentration of from 0.0005 to 2% w/w, 0.001 to 1.0% w/w, or 0.001 to 0.1% w/w, based on the total weight of the solution. At least one polymeric dispersant may be chosen from acrylic polymer, methacrylate polymer, carboxylic sulphonated polymer, carboxylic copolymer, carboxylic sulphonated nonionic terpolymer, phosphino polycarboxylic acid, and polymaleic polymer.

In one or more embodiments, the composition may comprise at least one corrosion inhibitor in a concentration of from 0.001 to 15% w/w, 0.001 to 5% w/w, 0.01 to 1% w/w, 0.01 to 0.5% w/w, or 0.02 to 0.22% w/w, based on the total weight of the solution. The at least one corrosion inhibitor may be chosen from sodium molybdate, sodium nitrite, chromates, borates, phosphates, polyphosphates, sodium benzoate, and a film forming composition. The preferred film forming composition comprises a hydrotrope with at least one of polyvinylpyrrolidone; ethoxylated alcohols having 3-6 moles of ethylene oxide (EO) alcohol ethoxylate, and a phosphate ester comprising (a) a hydrophilic polyoxyethylene chain having a range of PEO-3 to PEO-12 and an R-terminal group selected from the group consisting of a lipophilic alkyl chain having a range of C9 to C13 and a nonylphenol; (b) ethoxylated polyarylphenol phosphate having a polyoxyethylene chain of POE-16; (c) and a phosphate ester comprising an alkylphenoxy polyethoxyethanol.

In one or more embodiments, the composition my comprise a hydrotrope in a concentration of from 0.001 to 2% w/w, 0.001 to 1% w/w, or 0.01 to 0.01% w/w, based on the total weight of the solution. Non-limiting examples of suitable hydrotropes include sodium xylene sulfonate, a phosphate ester comprising (a) a hydrophilic polyoxyethylene chain having a range of PEO-3 to PEO-9 and an R-terminal group selected from the group consisting of a lipophilic alkyl chain having a range of C9 to C13 and a nonylphenol; (b) ethoxylated polyarylphenol phosphate having a polyoxyethylene chain of POE-16, and (c) a phosphate ester comprising an alkylphenoxy polyethoxyethanol.

In one or more embodiments, the composition my comprise composition may include from 0.1 to 20% w/w of a solvent such as a glycol or glycol ether (e.g. propylene glycol).

In one embodiment, a method in accordance with the first aspect of the invention is provided for reducing, destroying, or eliminating one or more reduced sulfur compounds, comprising the steps of contacting the reduced sulfur compound with an aqueous solution comprising chlorite and persulfate under conditions in which all or a part of the chlorite is converted into chlorine dioxide, thereby reducing, inactivating, destroying, or eliminating one or more reduced sulfur compounds.

In another embodiment, a method in accordance with the first aspect of the invention is provided for oxidizing one or more polymers, one or more reduced sulfur compounds or one or more reduced metals, comprises the steps of contacting the polymer, reduced sulfur compound or reduced metal with an aqueous solution comprising chlorite and persulfate under conditions in which all or a part of the chlorite is converted into chlorine dioxide, thereby oxidizing one or more polymers, one or more reduced sulfur compounds or one or more reduced metals.

In another embodiment, a method in accordance with the first aspect of the invention is provided for inactivating, destroying or killing one or more microbes, comprising contacting the microbe with an aqueous solution comprising chlorite and persulfate under conditions in which all or a part of the chlorite is converted into chlorine dioxide, thereby inactivating, destroying or killing one or more microbes.

The second aspect of the invention comprises a method for accelerating the in-situ generation of chlorine dioxide within the hydrocarbon recovery system by contacting the composition in accordance with the first aspect of the invention, with a source of bromide anions. Bromide anions catalyze the formation of chlorine dioxide thereby significantly accelerating the formation of chlorine dioxide. This aspect of the invention provides significant down-hole benefits in that it provides for accelerated generation of chlorine dioxide when, the formation fluid comprising an aqueous portion having bromide anions or other halides (e.g. chloride) in a catalytically effective concentration, is contacted by the composition in accordance with the first aspect of the invention. Formation fluids comprise an aqueous portion having high concentrations of dissolved solids. More specifically the dissolved solids comprise predominately halide salts (e.g. bromide and chloride). The composition introduced into the down-hole piping and geologic formation will be catalyzed by the presence of the catalyst, thereby accelerating the in-situ generation of chlorine dioxide. Bromide can also be added to the aqueous solution in accordance with the first aspect of the invention if a higher rate of reaction is desired earlier in the hydrocarbon recovery system.

In one embodiment, in accordance with the third aspect of the invention, the invention is suitable for remediation of sour wells. The souring of a well results in the formation of hydrogen sulfide that reduces the value of the recovered hydrocarbons, or altogether eliminates the ability to sell the hydrocarbons. Introducing a composition in accordance with the first aspect of the invention into the down-hole piping and geologic formation, and catalyzing the composition using the method in accordance with the second aspect of the invention, provides the opportunity to kill established sulfate reducing bacteria (SRB), oxidize and disperse the biofilms the SRBs are protected under, and oxidize the hydrogen sulfide, thereby remediating the problem and improving the permeability of the producing well. The implementation of the invention allows generation of chlorine dioxide within targeted zones of the hydrocarbon recovery system (e.g. geologic formation and down-hole piping).

DETAILED DESCRIPTION

DESCRIPTION OF THE FIGURES

FIG. 1—The UVNis spectrum of 30° C. aqueous solution comprising a 2:1 molar ratio of chlorite (reported as ClO₂ ⁻) to persulfate (reported as S₂O₈ ^(═)) respectively. The chlorite peak at 260 nm is representative of approximately 1450 ppm.

FIG. 2—The long dashed curve illustrates the change in the UV/Vis spectrum after 30 minutes. Temperature at the time of the scan was 35° C. Chlorine dioxide represented by the deviation at 360 nm wavelength is minimal. Hach DR 2800 measured 1.5 ppm.

FIG. 3—The short dashed curve illustrates the relatively small reduction in chlorite at the 260 nm peak and corresponding increase in chlorine dioxide at the 360 nm peak after 60 minutes and a temperature of 62° C. The chlorine dioxide peak at 360 nm represents 151 ppm as ClO₂ as measured by a Hach 2800 spectrophotometer.

FIG. 4—The curve represented by the symbol “+” illustrates the significant reduction in chlorite at the 260 nm peak and the corresponding increase in the area under the 360 nm peak representing chlorine dioxide after 120 minutes of reaction time and a temperature of 70° C.

FIG. 5—The UV/Vis spectra of 29° C. aqueous solution comprising a 2:1 molar ratio of chlorite (reported as ClO₂ ⁻) to persulfate (reported as S₂O₈ ^(═)) respectively. The chlorite peak at 260 nm is representative of approximately 30 ppm.

FIG. 6—The long dashed curve represents the UV/Vis spectrum for the aqueous solution at 51° C. after 15 minutes. There is no detectable level of chlorine dioxide. Hack spectrophotometer measurement confirmed the lack of chlorine dioxide 0.00 ppm using the low range setting. The deviation in between the dashed line and solid line are attributed to the temperature effects on the spectra analysis.

FIG. 7—The short dashed curve represents the UV/Vis spectrum for the aqueous solution at 69° C. after 30 minutes. There is no detectable level of chlorine dioxide. Hack spectrophotometer measurement confirmed the lack of chlorine dioxide 0.00 ppm using the low range setting.

FIG. 8—The heavy solid curve illustrates the detectable increase of chlorine dioxide peak at 360 nm and corresponding reduction of chlorite at the 260 nm after 90 minutes and a temperature of 77° C. 5 minutes after this sample was measured, 400 ppm of sodium bromide (NaBr) was added to the sample.

FIG. 9—The dense solid curve illustrates the measured increase of chlorine dioxide at the 360 nm peak and the corresponding reduction of chlorite 10 minutes (105 minutes total lapsed time) after adding the sodium bromide. Temperature was measured at 77° C.

FIG. 10—The curve represented by the symbol “x” illustrates the accelerated increase in chlorine dioxide resulting from addition of the bromide catalyst. Total lapsed time is 120 minutes (25 minutes after addition of bromide catalyst). Temperature remained at 77° C.

DISCUSSION OF FIGURES

FIGS. 1 and 2 illustrate the relative stability of the aqueous solution comprising chlorite anions (1450 ppm as ClO₂ ⁻) and persulfate anions to achieve a 2:1 molar ratio respectively after 30 minutes with a temperature of between 30° C. to 35° C. The measured pH at the start of the test was 8.4.

FIG. 3 illustrates the increase in chlorine dioxide as illustrated by the peak at 360 nm. The temperature increased from 35° C. to 62° C. over a 30 minute span. The graph clearly illustrates the increased reactivity of the chlorite and persulfate resulting from the elevation in temperature. FIG. 4 illustrates the continued increase in chlorine dioxide generation and reduction in chlorite concentration over a 30 minute period (compared to FIG. 3) in which the temperature increased from 62° C. to 70° C.

The data illustrated by FIGS. 1-4 are characteristic of the behavior in the rate of reaction and generation of chlorine dioxide resulting from transporting an aqueous solution of chlorite and persulfate down-hole to treat a petroleum recovery system with a relatively high (1450 ppm as ClO₂ ⁻) chlorite concentration. When the chlorite and persulfate are mixed and/or added to and contacted within the petroleum recovery system, the reaction between the chlorite and persulfate results after 30 minutes at between 30° C. to 35° C. is negligible. As the said aqueous solution is transported down-hole and temperatures increase toward 60° C. and greater, the rate of chlorine dioxide generation increases resulting in superior down-hole distribution of chlorine dioxide and treatment of the petroleum recovery system.

A comparison between FIGS. 5, 6 and 7 demonstrates the stability of the aqueous solution comprising 30 ppm as chlorite (reported as ClO₂ ⁻) and a sufficient amount of persulfate (reported a S₂O₈ ^(═)) to achieve a molar ration of 2:1 respectively over a 30 minute period (two 15 minute increments) as the temperature increases from 29° C. to 69° C. No discernible change in chlorine dioxide is detected by either the UV/Vis or Hach DR 2800 spectrophotometer. The deviation between the curves is believed to be the result of the effects caused by the change in the atomic internal energies (electron orbits) and their respective effect on the emission in the UV/Vis spectra.

FIGS. 8, 9 and 10 show the change in the area under the curves after addition of bromide ions demonstrating the increased rate of reaction resulting from the effect of the bromide catalyst while sustaining an equilibrium temperature of 77° C.

The data illustrated by FIGS. 5-10 demonstrate the benefits achieved resulting from the delayed in-situ generation of chlorine dioxide, especially as it pertains to the down-hole treatment of hydrocarbon recovery systems. When the aqueous solution is exposed to lower temperatures, it remains relatively stable. Detectable changes in chlorine dioxide concentration at 360 nm did not occur until significant time (approaching 105 minutes) had lapsed and the temperature increased from 69° C. to 77° C. When the heated aqueous solution was contacted with an effective amount of halogen catalyst (e.g. bromide anions), the rate of chlorine dioxide generation was significantly increased. This is relevant to down-hole treatment of hydrocarbon recovery systems since at least some portion (typically 40% or more) of the recovered formation fluid comprises an aqueous solution having high (typically from over 5,000 to over 250,000 ppm) concentrations of dissolved solids consisting primarily of halide based salts (e.g. chloride and bromide). The introduction of a catalytic amount of halides by the formation fluid results in generation of chlorine dioxide deep within the hydrocarbon recovery system (e.g. geologic formation and piping).

As used herein, “hydrocarbon recovery systems” includes the geologic formations, operations, and equipment used to access, acquire and recover hydrocarbons from hydrocarbon containing geologic formations. The hydrocarbon recovery system is selected from the group consisting of material that contains one or more solid, liquid, or gaseous hydrocarbons, a hydrocarbon deposit, a petroleum deposit, a hydrocarbon or petroleum product formation, a hydrocarbon or petroleum processing product or equipment, hydrocarbon recovery operations, or combinations thereof. As used herein, “hydrocarbon or petroleum processing product or equipment” is selected from the group consisting of one or more pieces of equipment for accessing, extracting, recovering, or processing hydrocarbons, a pipeline for transporting hydrocarbons and a vessel for storage of hydrocarbons.

As used herein, “hydrocarbon recovery applications” is selected from the group consisting of well drilling, hydraulic fracturing, water flooding, well stimulation, well remediation, pump desalination, and jet pump power fluid.

As used herein, “well remediation” describes an application wherein the composition in accordance with the first aspect of the invention is introduced to the hydrocarbon recovery system in sufficient concentration to killing bacteria, oxidizing biofilms and oxidizing hydrogen sulfide and other oxidizable organic and reduced sulfur compounds in the piping and geologic formation, thereby reducing or eliminating the presence of hydrogen sulfide in the formation fluid.

As used herein, “pump desalination” is an application in which water comprising relatively low concentrations of dissolved solids (typically less than 10,000 ppm) is pumped down-hole to dissolve and remove mineral salts from the pumps and piping.

As used herein, “jet pump power fluid” is the fluid (e.g. water or oil) used to power jet pumps used to extract formation fluid from the geologic formation.

As used herein, “water” can be an aqueous solution comprising dissolved solids, dissolved gases and the like. The use of the term water is not meant to represent only the pure form of water having the general formula H₂O.

As used herein “formation fluid” comprises fluids, (liquids and often gas) consisting of hydrocarbons and an aqueous solution. The hydrocarbons generally comprise petroleum based hydrocarbons (e.g. oil) and methane gas. The aqueous solution generally has a high level (greater than 10,000 ppm) of dissolved solids and some suspended solids. The dissolved solids within the aqueous solution primarily comprise halide salts such as chloride and bromide salts.

As used herein, “down-hole” is used to describe the portion of the hydrocarbon recovery system that is subterranean.

As used herein, “source of chlorite” describes any chemical compound that releases chlorite (having the general formula ClO₂ ⁻) when dissolved in an aqueous solution. Non-limiting examples of sources of chlorite include: chlorine dioxide, sodium chlorite, potassium chlorite and earth metal chlorites. The chlorine dioxide can be generated from any convenient means such as acidification and reduction of chlorates, or acidification and/or oxidation of chlorite. The source of chlorite can be a solid or a liquid.

As used herein, “chlorite” describes the precursor for generating chlorine dioxide, and has the general formula ClO₂ ⁻.

As used herein, “source of persulfate” describes any chemical compound that releases persulfate (having the general formula S₂O₈ ²⁻) when dissolved in an aqueous solution. Non-limiting examples of sources of persulfate include: sodium persulfate, potassium persulfate and ammonium persulfate. The source of persulfate can be a solid or a liquid. The persulfate may be coated (encapsulated) to delay the release of the persulfate until it is exposed to higher temperatures within the formation. The coating is typically an acrylic based polymer with silica or quartz embedded with the polymeric acrylic. Examples of coated persulfate suitable for use in the invention are available from Fritz Industries Inc. with locations in Dallas, Tex.

As used herein, “persulfate” describes the activator for generating chlorine dioxide, and has the general formula S₂O₈ ²⁻.

As used herein, “catalytically effective amount of halide” describes bromide and/or chloride anions in sufficient amount to react with persulfate to produce free bromine and/or free chlorine in acid pH conditions like those found in the aqueous portion of the formation fluid. Bromide has the general formula Br⁻, and chloride has the general formula Cl⁻. Free bromine comprises bromine gas (Br₂) and/or hypobromous acid (HOBr). Free chlorine comprises chlorine gas (Cl₂) and/or hypochlorous acid (HOCl).

As used herein, a biocide, or bactericide, is a substance that inhibits, destroys or kills bacteria.

As used herein, free residual level or residual is the amount of oxidant in a fluid present and available for microbiological control at a given time after the oxidant has reacted with background impurities and contaminants in the fluid. Free residual level or residual is generally described in units of percentage or ppm.

As used herein, “well fluid” is any fluid used in any of the drilling, completion, work over, fracturing and production of hydrocarbon recovery systems subterranean oil and gas wells.

The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprise” (and any form of comprise, such as “comprises” and “comprising”), “have” (and any form of have, such as “has” and “having”), “include” (and any form of include, such as “includes” and “including”), and “contain” (and any form contain, such as “contains” and “containing”) are open-ended linking verbs. As a result, a method or device that “comprises”, “has”, “includes” or “contains” one or more steps or elements possesses those one or more steps or elements, but is not limited to possessing only those one or more steps or elements. Likewise, a step of a method or an element of a device that “comprises”, “has”, “includes” or “contains” one or more features possesses those one or more features, but is not limited to possessing only those one or more features. Furthermore, a device or structure that is configured in a certain way is configured in at least that way, but may also be configured in ways that are not listed.

For the purposes of promoting an understanding of the principles of the invention, reference will now be made to embodiments of the invention and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the invention is thereby intended, and any alterations and further modifications in the described embodiments, and any further applications of the principles of the invention as illustrated therein as would normally occur to one skilled in the art to which the invention relates are contemplated an protected.

According to one or more embodiments of the invention, chlorine dioxide is generated in situ in a hydrocarbon recovery system. According to one aspect of the invention, the hydrocarbon recovery system is found down-hole within a hydrocarbon-bearing subterranean formation and is within the formation where the target compounds, or contaminants, are located. The hydrocarbon recovery system may also comprise a hydrocarbon deposit, a petroleum deposit, a hydrocarbon or petroleum product formation, or a hydrocarbon or petroleum processing product or equipment. As used herein, the target compounds, or contaminants, are agents located within the hydrocarbon recovery system that have the potential or propensity to cause damage to or restriction of the petroleum production process, and include high-molecular weight polymers (e.g. polyacrylamides, carboxy-methylcellulose, hydroxyethylcellulose, CMC, HPG, and Zanthan), microbes (e.g. anaerobic and aerobic bacteria), sulfur, iron sulfide, hydrogen sulfide and similar compounds.

One embodiment of this invention provides for a method for the in-situ generation of chlorine dioxide in hydrocarbon recovery systems, said method comprising the steps of combining a source of chlorite, a source of persulfate, and water to form a composition; the molar ratio of chlorite (having the general formula ClO₂ ⁻) to persulfate (having the general formula S₂O₈ ^(═)) being greater than 0.5:1, more preferably greater than or equal to 1:1, and most preferred greater than or equal to 2:1; introducing said composition into a hydrocarbon recovery system; achieving a temperature of greater than 100° F., and wherein all or part of the chlorite is converted to chlorine dioxide in the hydrocarbon recovery system.

One or more embodiments of the invention, which incorporate this method for the in-situ generation of chlorine dioxide into a fracturing fluid, thus provide an in-situ method for generating and using chlorine dioxide as a polymer oxidant and down-hole biocide that does not deplete or attenuate the friction-reducing components of the fracturing fluid until the generation of chlorine dioxide is accelerated by elevated temperature. In these embodiments, the chlorine dioxide acts as a polymer oxidant and down-hole biocide.

Although not required, in one or more embodiments, the composition in accordance with the first aspect of the invention (herein after “composition”) may further comprise at least one nonionic surfactant in a concentration of from 0.005 to 3% w/w, preferably from 0.01 to 2% w/w, more preferably from 0.02 to 1% w/w, based on the total weight of the solution. Furthermore, the at least one nonionic surfactant is preferably chosen from (a) ethoxylated alcohols and alkylglycosides having a hydrophile lypohile balance from 5 to 15, which may be a C6-C10 alkyl, 3-9 moles of ethylene oxide (EO) alcohol ethoxylate; and (b) a sufficiently water-soluble block copolymer of ethylene oxide or propylene oxide.

In one or more embodiments, the composition may further comprise at least one cation sequestering agent in a concentration of from 0.0001 to 1.0% w/w, preferably from 0.0005 to 0.1% w/w, more preferably from 0.001 to 0.01% w/w, based on the total weight of the solution. The cation sequestering agent may be 1-hydroxyethylidene-1,1-diphosphonic acid, or phosphonobutane tricarboxylic acid.

In one or more embodiments of the invention, the composition may contain at least one anionic surfactant chosen from (a) C8-C16 alkyl benzene sulfonic acids and alkali metal, alkaline earth metal, ammonium or alkylamine salts thereof; (b) C8-C18 alkyl sulfonic acid; (c) C8-C16 alkyl sulfates; and (d) C6-C12 alkyl diphenyl oxide sulfonate surfactants, in a concentration of from 0.001 to 1% w/w, or from 0.01 to 0.5% w/w, based on the total weight of the solution. The at least one anionic surfactant may be an alkyl benzene sulfonic acid and, preferably, dodecyl benzene sulfonic acid.

In one or more embodiments of the invention, the composition may comprise at least one polymeric dispersant in a concentration of from 0.0005 to 2% w/w, 0.001 to 1.0% w/w, or 0.001 to 0.1% w/w, based on the total weight of the solution. At least one polymeric dispersant may be chosen from acrylic polymer, methacrylate polymer, carboxylic sulphonated polymer, carboxylic copolymer, carboxylic sulphonated nonionic terpolymer, phosphino polycarboxylic acid, and polymaleic polymer.

In one or more embodiments of the invention, the composition may further contain at least one corrosion inhibitor in a concentration of from 0.001 to 15% w/w, 0.001 to 5% w/w, 0.01 to 1% w/w, 0.01 to 0.5% w/w, or 0.02 to 0.22% w/w, based on the total weight of the solution. The at least one corrosion inhibitor may be chosen from sodium molybdate, sodium nitrite, chromates, borates, phosphates, polyphosphates, sodium benzoate, and a film forming composition. The preferred film forming composition comprises a hydrotrope with at least one of polyvinylpyrrolidone; ethoxylated alcohols having 3-6 moles of ethylene oxide (EO) alcohol ethoxylate, and a phosphate ester comprising (a) a hydrophilic polyoxyethylene chain having a range of PEO-3 to PEO-12 and an R-terminal group selected from the group consisting of a lipophilic alkyl chain having a range of C9 to C13 and a nonylphenol; (b) ethoxylated polyarylphenol phosphate having a polyoxyethylene chain of POE-16; (c) and a phosphate ester comprising an alkylphenoxy polyethoxyethanol.

In one or more embodiments of the invention, the composition may further contain a hydrotrope in a concentration of from 0.001 to 2% w/w, 0.001 to 1% w/w, or 0.01 to 0.01% w/w, based on the total weight of the solution. Non-limiting examples of suitable hydrotropes include sodium xylene sulfonate, a phosphate ester comprising (a) a hydrophilic polyoxyethylene chain having a range of PEO-3 to PEO-9 and an R-terminal group selected from the group consisting of a lipophilic alkyl chain having a range of C9 to C13 and a nonylphenol; (b) ethoxylated polyarylphenol phosphate having a polyoxyethylene chain of POE-16, and (c) a phosphate ester comprising an alkylphenoxy polyethoxyethanol.

In one or more embodiments of the invention, the composition may include from 0.1 to 20% w/w of a solvent such as a glycol or glycol ether (e.g. propylene glycol).

Because the chlorine dioxide is generated in-situ as temperature rise and/or catalyst is contacted, all of which occurs down-hole, in one or more embodiments of this invention, no ex situ generator or process is required to generate chlorine dioxide for injection into the hydrocarbon recovery system in order to destroy or reduce polymers, sulfur, reduced sulfur compounds, phenols and other compounds, although it remains optional.

Another embodiment of the invention is the stimulation of petroleum recovery systems (e.g. hydrocarbon containing geologic formation) to increase the flow-rate of formation fluids. Chlorine dioxide oxidizes bio-films and chemically reducible compounds that restrict flow, thereby improving permeability within the formation.

In one or more embodiments of the invention, a method is provided for accelerating the in-situ generation of chlorine dioxide within the hydrocarbon recovery system by contacting the composition with a catalytically effective amount of halide (e.g. bromide anions). Catalyst like bromide anions often present in the aqueous portion of the formation fluid accelerate the generation of chlorine dioxide. This aspect of the invention provides significant down-hole benefits in that it provides for accelerated generation of chlorine dioxide when, the formation fluid comprising an aqueous portion having bromide anions or other halides (e.g. chloride) in a catalytically effective concentration, is contacted by the composition in accordance with the first aspect of the invention. Formation fluids comprise an aqueous portion having high concentrations of dissolved solids. More specifically the dissolved solids comprise predominately halide salts (e.g. bromide and chloride). The composition introduced into the down-hole piping and geologic formation will be catalyzed by the presence of the catalyst, thereby accelerating the in-situ generation of chlorine dioxide. Bromide can also be added to the aqueous solution in accordance with the first aspect of the invention if a higher rate of reaction is desired earlier in the hydrocarbon recovery system.

In one embodiment, a method is provided for remediation of sour wells. The souring of a well results in the presence of sulfate reducing bacteria that form hydrogen sulfide which lowers the value of the recovered hydrocarbons, or altogether eliminates the ability to sell the recovered hydrocarbons such as contaminated methane gas. Introducing the composition into the down-hole piping and geologic formation provides the opportunity to kill established sulfate reducing bacteria (SRB), oxidize and disperse the biofilms the SRBs are protected under, and oxidize the hydrogen sulfide, thereby remediating the problem and improving the permeability of the producing well. The implementation of the invention allows generation of chlorine dioxide within geologic formation and piping.

Embodiments of the present invention also provide for the composition to be either added to or premixed with a fluid stream, for example a fluid stream being injected into a hydrocarbon recovery system such as a subterranean wellbore, wherein said fluid stream may include other additives, such as friction reducers, wetting agents, polymers, corrosion inhibitors, sand, proppants, biocides, breakers and other chemicals. The chlorine dioxide within the fluid remains sufficiently low as to not compromise the performance of these additives. As the fluid is introduced to temperatures exceeding 100° F., the in-situ generation of chlorine dioxide takes place, providing chlorine dioxide throughout the wellbore. When the fluid is introduced into the geologic formation and subsequently contacted with formation fluid comprising a catalytically effective amount of halide (e.g. bromide), the rate of in-situ generation of chlorine dioxide is increased, thereby generating chlorine dioxide at a higher rate. The in situ generated chlorine dioxide will then destroy polymers and other target compounds, such as reduced sulfur compounds, biomass (e.g. microbes, bacteria), sulfur, phenols, either within, around or after said geologic formation, such that the chlorine dioxide generation reaction that initiates in said geologic formation will consume the contaminants.

In one embodiment, the composition is premixed offsite and is then transported to the work site. In other embodiments, for example during a hydraulic fracturing operation, said composition can be premixed at the work site in one of the frac tanks, in the blender. The premixed composition comprising the chlorite and persulfate and other additives is then injected into the process stream via a chemical injector system and/or other method that is known to those skilled in the art.

In another embodiment, the composition can be produced by separately adding the source of chlorite and the source of persulfate to the process stream comprising predominantly water. When chlorine dioxide is added directly to well fluids (i.e. fracturing fluids) or other fluid streams, they can initially react with dissolved organic and inorganic compounds in the water, thus depleting the amount of free residual available as a biocide and for other intended treatment purposes. Therefore, in one or more embodiments of the present invention, it will be necessary to add an excess of the composition in order to produce a free residual of the chlorine dioxide sufficient to achieve the desired bacterial control and/or oxidation of complex organics. In yet another embodiment, if instant biocidal control is desired or required, the composition may be incorporated into water or fluid stream that has already has been dosed with a generated solution of chlorine dioxide or other biocidal agent. More specifically, and by way of example only, chlorine dioxide concentrations of 10 to 20 mg/l or less do not impact the performance of the additives, such polymer(s) or other drag reduction additives, in fracturing fluids. Therefore, in certain embodiments, the composition can be added to raw fracturing water that contains a sufficient residual of chlorine dioxide, for example from about 0.02 to 5 mg/l, and preferably from about 1-2 mg/l, to provide primary disinfection of the raw water without prematurely depleting or effecting the performance of the other additives. The addition of this low-residual, generated chlorine dioxide provides primary disinfection and inhibits or prevents biofouling of the mixing and pumping equipment. In this example, the composition may be formulated to provide excess persulfate (e.g. 1:1 ratio) to benefit from the existing chlorite in the fluid. The fluid pretreated with chlorine dioxide will reduce most of the chlorine dioxide resulting in a residual of chlorite anions. The invention provides for the ability to regenerate the chlorite down-hole to provide better economy and treatment of the down-hole hydrocarbon recovery system.

Although the embodiments disclosed hereinabove often refer to the hydrocarbon recovery system as located down-hole within a subterranean formation, in accordance with alternate embodiments that are within the scope of the invention, the hydrocarbon recovery system can also be equipment, a pipeline or vessel for extracting, processing, refining, transporting or storage of hydrocarbons.

Although the above description has focused on the use of in situ generation of chlorine dioxide via the stable precursor composition disclosed herein to effectuate the removal of hydrocarbons during oil and gas production, the composition and method for using the same in accordance with this invention can also be applied and used in connection with the production of other petroleum products.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. 

I claim:
 1. A method for the in-situ generation of chlorine dioxide in hydrocarbon recovery systems, said method comprising the steps of combining a source of chlorite, a source of persulfate and water to form a composition; the molar ratio of chlorite (having the general formula ClO₂ ⁻) to persulfate (having the general formula S₂O₈ ^(═)) being greater than 0.5:1; introducing said composition into a hydrocarbon recovery system; achieving a temperature of greater than 100° F., and wherein all or part of the chlorite is converted to chlorine dioxide within the hydrocarbon recovery system.
 2. The method of claim 1, wherein said hydrocarbon recovery system is selected from the group consisting of geological material that contains one or more solid, liquid, or gaseous hydrocarbons, a hydrocarbon deposit, a petroleum deposit, a hydrocarbon or petroleum product formation, and a hydrocarbon or petroleum processing product or equipment, or combinations thereof.
 3. The method of claim 2, wherein the hydrocarbon or petroleum processing product or equipment is selected from the group consisting of one or more pieces of equipment for extracting, processing, or refining hydrocarbons, a pipeline for transporting hydrocarbons and a vessel for storage of hydrocarbons.
 4. The method of claim 1, wherein the molar ratio of chlorite to persulfate is great than or equal to 1:1.
 5. The method of claim 1, wherein the molar ratio of chlorite to persulfate is greater than or equal to 2:1.
 5. The method of claim 1, wherein the chlorine dioxide is sufficient to reduce, inactivate, destroy, or eliminate at least one or more reducing agents, polymers or microbes in the hydrocarbon recovery system.
 6. The method of claim 1, wherein the composition is in sufficient amount to perform well remediation.
 7. The method of claim 1, wherein the hydrocarbon recovery system further comprises formation fluid having a catalytically effective amount of halide.
 8. The method of claim 7, wherein the catalytically effective amount of halide is selected from at least one of bromide and chloride anions.
 8. The method of claim 1, wherein the source of chlorite comprises chlorine dioxide.
 9. The method of claim 1, wherein the source of chlorite is sodium chlorite.
 10. The method of claim 1, wherein the source of persulfate is selected from at least one of sodium or potassium persulfate.
 11. The method of claim 1, wherein the source of persulfate is selected from ammonium persulfate.
 12. The method of 7, wherein the catalytically effective amount of halide is bromide.
 13. The method of claim 1, wherein the source of chlorite is in an aqueous solution.
 14. The method of claim 1, wherein the source of persulfate is in an aqueous solution.
 15. The method of claim 1, wherein the source of chlorite is in a solid form.
 16. The method of claim 1, wherein the source of persulfate is in a solid form.
 17. The method of claim 1, wherein the composition further comprises at least one additive selected from at least one hydrotrope, surfactant, dispersant, chelant, sequestrant, and acid.
 18. The method of claim 17, wherein the additive is a phosphate ester comprising (a) a hydrophilic polyoxyethylene chain having a range of PEO-3 to PEO-9 and an R-terminal group selected from the group consisting of a lipophilic alkyl chain having a range of C9 to C13 and a nonylphenol; (b) ethoxylated polyarylphenol phosphate having a polyoxyethylene chain of POE-16, and (c) a phosphate ester comprising an alkylphenoxy polyethoxyethanol. 